A method for identifying carbon dioxide penetration and optimizing fracturing construction parameters of an oil and gas reservoir

Abstract

The application discloses a method for identifying carbon dioxide penetration enhancement and optimizing fracturing construction parameters of an oil and gas reservoir, and the method comprises the following steps: according to the reservoir type of a target reservoir, selecting a gas reservoir, an oil reservoir static, and an oil reservoir dynamic evaluation process to perform experiments to obtain experimental parameters; when performing the experiments, under the same temperature, pressure, action time, and fluid saturation state conditions, at least three different carbon dioxide molar fraction groups are set, and experiments are repeated under each group; and the carbon dioxide penetration enhancement contribution is determined according to the experimental parameters. The application can quantitatively identify water lock damage, sensitivity damage, injected water damage, and residual oil retention damage, decompose the contributions of hole expansion penetration enhancement, water lock solution, sensitivity solution penetration enhancement, and residual oil production, establish a carbon dioxide molar fraction-reservoir reconstruction effect response relationship, determine an optimal carbon dioxide molar fraction window, and combine a flow-solid-thermal-chemical multi-field coupling carbon dioxide fracturing-stand-by well model to optimize carbon dioxide fracturing construction parameters.

Description

Technical Field

[0001] This invention relates to the field of reservoir damage assessment and carbon dioxide production enhancement technology for oil and gas reservoirs, and particularly to a method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs and optimizing fracturing construction parameters. Background Technology

[0002] Carbon dioxide fracturing, carbon dioxide huff and puff, supercritical carbon dioxide immersion, and carbon dioxide displacement technologies have been gradually applied to the production enhancement and stimulation of oil and gas reservoirs in tight sandstone, shale, low-permeability sandstone, carbonate rocks, and coal. However, during the production enhancement and stimulation process, under high temperature and high pressure conditions, carbon dioxide can form a carbonate system with formation water, and further react with carbonate minerals, feldspar minerals, and some clay minerals in the rock, inducing mineral dissolution, pore throat structure reconstruction, changes in wettability, and alterations in permeability. Therefore, it is urgent to clarify the effects of carbon dioxide on the pore-enlarging, permeability-enhancing, and damage-reducing effects of the reservoir matrix.

[0003] During the action of carbon dioxide, the types of damage and sources of permeability enhancement in gas and oil reservoirs differ significantly. For gas reservoirs, damage from core water-locking, sensitivity damage from fracturing fluid filtrate, carbon dioxide-induced pore-throat expansion, water-lock release, and sensitivity relief may all coexist. For oil reservoirs, in addition to bound water damage, injected water damage, and sensitivity damage, residual oil retention also occupies pore throats and seepage channels. After carbon dioxide action, residual oil can be partially released through processes such as swelling, viscosity reduction, extraction, reduced interfacial tension, and displacement, thereby further improving gas or liquid phase permeability. These multiple effects often overlap, meaning that permeability changes after carbon dioxide action no longer correspond to a single mechanism.

[0004] Existing methods for evaluating carbon dioxide reservoir stimulation often rely on changes in core permeability, porosity, mineral composition, or microstructure before and after treatment to assess the stimulation effect. These methods typically only provide an overall increase in permeability after carbon dioxide treatment, failing to differentiate between contributions from pore enlargement, water-lock removal, relief of sensitive mineral damage, and residual oil disposal. Especially in water- or oil-bearing conditions, the increase in effective gas-phase permeability in the core may originate from pore throat enlargement, reduced bound water, altered wettability, relief of sensitive mineral damage, or disposal of residual oil. Using only changes in gas or liquid permeability as the evaluation criterion easily conflates multiple effects into a single overall result, failing to accurately identify the true stimulation mechanism of carbon dioxide in gas and oil reservoirs, and hindering the reliable basis for optimizing in-situ fracturing, huff and puff, and displacement parameters.

[0005] Furthermore, existing research and evaluation methods often use pure carbon dioxide or a single carbon dioxide concentration as experimental conditions. However, in actual reservoirs, injected carbon dioxide mixes, dissolves, diffuses, and migrates with hydrocarbon gases, formation water, crude oil, or working fluids, causing variations in the carbon dioxide molar fraction at different locations and stages of the reaction. Therefore, the reservoir matrix is ​​not always subjected to pure carbon dioxide, but rather to carbon dioxide-water-rock or carbon dioxide-water-oil-rock interactions under different carbon dioxide molar fraction conditions. The carbon dioxide molar fraction affects carbonic acid formation, solution acidity, mineral dissolution rate, secondary mineral precipitation, wettability regulation, bound water release, and residual oil mobilization. Its impact on reservoir stimulation is usually not a simple linear enhancement relationship.

[0006] At low carbon dioxide molar fractions, the carbon dioxide-water-rock reaction intensity is insufficient, resulting in weak pore-throat dissolution, changes in wettability, and water-lock removal. Within a moderate carbon dioxide molar fraction range, mineral dissolution and pore enlargement, improved pore-throat connectivity, a shift in wettability from strong to weak or neutral water-wetting, reduction of bound water, and residual oil mobilization may produce synergistic permeability enhancement effects. However, at excessively high carbon dioxide molar fractions, overly strong water-rock reactions may induce secondary mineral precipitation, fine-grained migration, localized pore-throat blockage, or saturation of wettability regulation, causing the permeability enhancement effect to cease or even decline. Therefore, evaluating the treatment effect solely under pure carbon dioxide conditions is insufficient to reflect the nonlinear impact of carbon dioxide molar fraction changes on matrix modification effects in actual reservoirs. Summary of the Invention

[0007] To address the aforementioned problems, this invention aims to provide a method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs and optimizing fracturing construction parameters.

[0008] The technical solution of the present invention is as follows: On the one hand, a method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs is provided, including the following steps: Based on the reservoir type of the target reservoir, either a gas reservoir evaluation process or an oil reservoir evaluation process is selected to conduct experiments and obtain experimental parameters. The oil reservoir evaluation process includes a static oil reservoir evaluation process and / or a dynamic oil reservoir evaluation process. During the experiment, at least three different carbon dioxide molar fraction groups were set up under the same temperature, pressure, action time and fluid saturation conditions. The carbon dioxide molar fraction groups were formed by mixing carbon dioxide with one or more of nitrogen, methane, air or formation gas, and the total pressure of each group was kept consistent. The experiment was repeated under each carbon dioxide molar fraction group. The contribution of carbon dioxide to osmosis was determined based on the experimental parameters.

[0009] Preferably, the gas reservoir evaluation process includes the following sub-steps: S11: Obtain at least two standard cores with similar physical properties from the target reservoir and divide them into Group A cores and Group B cores; S12: The core samples from Group A and Group B were pretreated, and their initial absolute permeability under dry conditions was measured and denoted as K. GA1 and K GB1 ; S13: Prepare simulated formation water and fracturing fluid filtrate respectively. Saturate the core sample of group A with the simulated formation water to establish a bound water state, and saturate the core sample of group B with the fracturing fluid filtrate to establish a bound liquid state. Measure the effective gas-phase permeability under the bound state and record it as K. GA2 and K GB2 ; S14: Under target conditions, the core samples from Group A and Group B were subjected to supercritical carbon dioxide immersion. After immersion, the effective gas phase permeability of the core samples while maintaining a liquid-containing state was measured and denoted as K. GA3 and K GB3 ; S15: Dry the core and determine the absolute permeability of the core after drying, denoted as K. GA4 and K GB4 .

[0010] As a preferred method, when determining the contribution of carbon dioxide permeation enhancement based on the experimental parameters, the water-locking damage rate D of the core samples from group A is calculated using the following formula. Gw : (1) The permeability enhancement rate I of the core samples from group A is calculated using the following formula. Gp : (2) The water-locking permeability enhancement rate I of the core samples from group A is calculated using the following formula. Gw : (3) The combined damage rate D of water lock and sensitivity in the core samples of Group B was calculated using the following formula. Gt : (4) The pore enlargement and desensitization permeability enhancement rate I of the B group core samples after carbon dioxide treatment is calculated using the following formula. GBd : (5) The dewatering and desensitization permeability enhancement rates (I) of the B group core samples after carbon dioxide treatment are calculated using the following formula. GBw : (6) The sensitivity damage rate D of the core samples from group B is calculated using the following formula. Gs: (7) The dry-state solution-sensitive permeability enhancement rate I of the B group cores was calculated using the following formula. GBs,d : (8) The permeability enhancement rate (I) of the B group core samples was calculated using the following formula. GBs,w : (9).

[0011] Preferably, the reservoir static evaluation process includes the following sub-steps: S21: Obtain at least two standard cores with similar physical properties from the target reservoir and divide them into Group A cores and Group B cores; S22: The core samples from Group A and Group B were pretreated, and their initial absolute gas permeability under dry conditions was measured and denoted as K. OA1 and K OB1 ; S23: Establish a bound water state for the core samples from group A, and establish a bound water-residual oil state for the core samples from group B. Measure the effective gas-phase permeability under the bound water state, and denote it as K. OA2 and K OB2 ; S24: Under target conditions, the core samples from Group A and Group B were subjected to supercritical carbon dioxide immersion. After immersion, the effective gas permeability of the core samples under confined conditions was measured and denoted as K. OA3 and K OB3 ; S25: Dry the core and measure its absolute permeability after drying, denoted as K. OA4 and K OB4 .

[0012] Preferably, when determining the contribution of carbon dioxide permeability enhancement based on the experimental parameters, the permeability enhancement rate I of the core sample from group A is calculated using the following formula. OAp : (10) The bound water damage rate D of the core samples from group A was calculated using the following formula. OAw : (11) The water-locking permeability enhancement rate I of the core samples from group A is calculated using the following formula. OAw : (12) The overall damage rate D of the core samples from group B is calculated using the following formula. OBt : (13) The permeability enhancement rate I of the core samples from group B is calculated using the following formula. OBp : (14) The combined permeability enhancement rate I of the core samples from Group B, calculated using the following formula, is obtained by dewatering and derelict residual oil. OBwr : (15) The residual oil damage rate D of the B group core samples was calculated using the following formula. Or : (16) The residual oil contribution rate I of the B group core samples was calculated using the following formula. Or,r : (17).

[0013] Preferably, the reservoir dynamic evaluation process includes the following sub-steps: S31: Obtain at least two standard cores with similar physical properties from the target reservoir and divide them into Group A cores and Group B cores; S32: The core samples from Group A and Group B were pretreated, and their initial absolute gas permeability under dry conditions was measured and denoted as K. DA1 and K DB1 ; S33: For the saturated or simulated formation water in the core samples of Group A, determine the formation water permeability, denoted as K. DA2 ; The B group core was saturated with simulated formation water, then saturated with formation oil or simulated oil, and displaced using formation water or simulated formation water to establish a residual oil state. The effective permeability of the aqueous phase under the residual oil state was measured and denoted as K. DB2 ; S34: Displace distilled water, inject water, or working fluid into the core samples from Group A and Group B, respectively. After displacing 10-15 PV, maintain the temperature and pressure under simulated reservoir temperature and pressure conditions, and measure the liquid permeability, denoted as K. DA3 and K DB3 ; S35: Nitrogen gas was injected into the core samples from Group A and Group B respectively until no water flow was observed at the outlet. The effective gas-phase permeability under bound water conditions was measured and recorded as K. DA4 and K DB4 ; S36: Under target conditions, supercritical carbon dioxide displacement was performed on the core samples from Group A and Group B. The initial effective gas phase permeability of the carbon dioxide displacement was recorded and denoted as K. DA5 and K DB5 And the stable gas phase effective permeability, denoted as K.DA6 and K DB6 ; S37: After carbon dioxide displacement until permeability stabilizes, the effective gas phase permeability is remeasured using nitrogen and denoted as K. DA7 and K DB7 ; S38: Displace formation water or simulated formation water into the core samples from Group A and Group B respectively, and measure the liquid permeability after the action of carbon dioxide, denoted as K. DA8 and K DB8 ; S39: Dry the core and measure the absolute gas permeability of the dried core, denoted as K. DA9 and K DB9 .

[0014] Preferably, when determining the contribution of carbon dioxide permeation enhancement based on the experimental parameters, the injection water damage rate D of the core samples from group A is calculated using the following formula. DAw : (18) The comprehensive damage rate D of the gas phase channel under the combined effects of bound water and sensitivity in the core samples of Group A is calculated using the following formula. DAg : (19) The comprehensive recovery rate of the carbon dioxide seepage channels affected by core enlargement, water-lock removal, and desensitization in Group A was calculated using the following formula. : (20) The recovery rate of the nitrogen retest channel due to the effects of core enlargement, water-lock removal, and desensitization on group A was calculated using the following formula. : (twenty one) The recovery rate I of carbon dioxide effect on the liquid seepage channel in the core samples of Group A was calculated using the following formula. DA,l : (twenty two) The porosity I of the dry gas seepage channel in the core of Group A is calculated using the following formula. DA,p : (twenty three) The injection water damage rate D under the condition of residual oil presence in the core samples of Group B is calculated using the following formula. DBw : (twenty four) The comprehensive damage rate D of the gas phase channel under the combined effects of residual oil, bound water, and sensitivity in the B group core was calculated using the following formula. DBg : (25) The comprehensive recovery rate of carbon dioxide seepage channels in the B group cores was calculated using the following formula. : (26) The comprehensive recovery rate of the nitrogen retest channel in Group B cores was calculated using the following formula. : (27) The comprehensive recovery rate I of the fluid seepage channels in the B group cores was calculated using the following formula. DB,l : (28) The porosity I of the dry gas seepage channel in the B group core was calculated using the following formula. DB,p : (29) The contribution of residual oil to the restoration of carbon dioxide seepage channels was calculated using the following formula. : (30) The contribution of residual oil to the recovery of the nitrogen retest channel was calculated using the following formula. : (31) The contribution of residual oil to the restoration of the liquid seepage channel is calculated using the following formula. : (32).

[0015] Preferably, the standard cores with similar physical properties meet at least one of the following conditions: the difference in initial permeability does not exceed 20%, the difference in porosity does not exceed 10%, the difference in the position of the main peak in the nuclear magnetic resonance T2 spectrum does not exceed 20%, and the difference in the content of major minerals does not exceed 15%.

[0016] On the other hand, a method for optimizing carbon dioxide fracturing construction parameters for oil and gas reservoirs is also provided, including the following steps: S1: Using any one of the above-mentioned methods for identifying carbon dioxide permeability enhancement in oil and gas reservoirs, determine the carbon dioxide permeability enhancement contribution parameters and normalize the carbon dioxide permeability enhancement contribution parameters. S2: Construct a comprehensive renovation index model, and calculate the comprehensive renovation index under different carbon dioxide mole fractions based on the comprehensive renovation index model; S3: Select the range of carbon dioxide mole fraction corresponding to the threshold of the comprehensive transformation index as the recommended carbon dioxide mole fraction window of the target reservoir; S4: Input the recommended carbon dioxide mole fraction window and the corresponding carbon dioxide permeability enhancement contribution parameters into the fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-steaming model, simulate and evaluate different combinations of carbon dioxide fracturing construction parameters, and determine the recommended carbon dioxide fracturing construction parameters for the target reservoir based on the evaluation results. The fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-well shut-in model is as follows: (33) In the formula: A fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-well shut-in model; This refers to the combination of parameters for carbon dioxide fracturing operations. For stress tensor; This is a physical activity item; For total damage variable; This represents the initial elastic stiffness tensor in the undamaged state. This is the total strain tensor; This is the initial strain tensor; The coefficient of thermal expansion of the rock; For temperature; For reference temperature; Unit tensor; Porosity; t is the fluid density; t is time. Darcy flow velocity; For quality source items; For penetration rate; For fluid viscosity; Pore ​​pressure; Equivalent volumetric heat capacity; The specific heat capacity at constant pressure of the fluid; It is the equivalent thermal conductivity; For heat source items; This represents the carbon dioxide diffusion flux; This refers to the molar concentration of carbon dioxide. For the reaction term; For source and sink items; The effective diffusion coefficient; This represents the mole fraction of carbon dioxide. Initial penetration rate; Initial porosity; The permeability evolution factor is determined by both the mole fraction of carbon dioxide and the reaction time.

[0017] Preferably, when the oil and gas reservoir carbon dioxide permeability enhancement identification method in step S1 uses the gas reservoir evaluation process to obtain experimental parameters, the comprehensive stimulation index model in step S2 is: (34) In the formula: The comprehensive transformation index under the gas reservoir evaluation process; The mole fraction of carbon dioxide; Normalized pore-expanding permeability enhancement rate; To normalize and resolve water-locking and infiltration rate; To normalize and resolve the sensitive permeability rate; When, in step S1, the method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs uses the reservoir static evaluation process to obtain experimental parameters, the comprehensive stimulation index model in step S2 is: (35) In the formula: The comprehensive stimulation index under the static evaluation process of the reservoir; Normalized pore-expanding permeability enhancement rate; To normalize and resolve water-locking and infiltration rate; Contribution rate to normalized residual oil utilization; When, in step S1, the oil and gas reservoir carbon dioxide permeability enhancement identification method uses the reservoir dynamic evaluation process to obtain experimental parameters, the comprehensive stimulation index model in step S2 is: (36) In the formula: The comprehensive stimulation index under the dynamic evaluation process of oil reservoirs; The normalized overall recovery rate of carbon dioxide seepage channels; The normalized nitrogen retest channel comprehensive recovery rate; The normalized overall recovery rate of the liquid seepage channel; The normalized porosity of the dry gas seepage channel.

[0018] The beneficial effects of this invention are: This invention can quantitatively identify water-lock damage, sensitivity damage, injected water damage, and residual oil retention damage by using multi-state permeability and porosity-permeability response relationships. It decomposes the contributions of porosity expansion and permeability enhancement, water-lock removal, sensitivity removal and permeability enhancement, and residual oil mobilization, and establishes a carbon dioxide mole fraction-reservoir stimulation effect response relationship to determine the optimal carbon dioxide mole fraction window for the target reservoir. This provides technical support for optimizing construction parameters during carbon dioxide fracturing, huff and puff, soaking, and displacement processes. Furthermore, this invention inputs the carbon dioxide mole fraction window and permeability enhancement contribution parameters determined by core experiments into a fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-well-shutting model. It simulates and optimizes construction parameters such as pumping rate, total carbon dioxide injection, construction pressure, injection time, well-shutting time, section length, cluster spacing, number of clusters per section, and the mixing ratio of carbon dioxide and auxiliary gas. This allows the carbon dioxide permeability enhancement contribution obtained at the experimental scale to be further transformed into a carbon dioxide fracturing construction scheme for the target reservoir. Attached Figure Description

[0019] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0020] Figure 1 This is a schematic diagram of the gas reservoir evaluation process in a specific embodiment; Figure 2 This is a flowchart illustrating the reservoir static evaluation process in a specific embodiment. Figure 3 This is a flowchart illustrating the reservoir dynamic evaluation process in a specific embodiment. Detailed Implementation

[0021] The present invention will be further described below with reference to the accompanying drawings and embodiments. It should be noted that, unless otherwise specified, the embodiments and technical features described in this application can be combined with each other. It should also be pointed out that, unless otherwise indicated, all technical and scientific terms used in this application have the same meaning as commonly understood by one of ordinary skill in the art to which this application pertains. The terms "comprising" or "including" and similar words used in this invention refer to elements or objects preceding the word that encompass the elements or objects listed following the word and their equivalents, without excluding other elements or objects.

[0022] On the one hand, the present invention provides a method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs, comprising the following steps: Based on the reservoir type of the target reservoir, either a gas reservoir evaluation process or an oil reservoir evaluation process is selected to conduct experiments and obtain experimental parameters. The oil reservoir evaluation process includes a static oil reservoir evaluation process and / or a dynamic oil reservoir evaluation process. During the experiment, at least three different carbon dioxide molar fraction groups were set up under the same temperature, pressure, action time and fluid saturation conditions. The carbon dioxide molar fraction groups were formed by mixing carbon dioxide with one or more of nitrogen, methane, air or formation gas, and the total pressure of each group was kept consistent. The experiment was repeated under each carbon dioxide molar fraction group. The contribution of carbon dioxide to osmosis was determined based on the experimental parameters.

[0023] In this invention, the gas reservoir evaluation process can evaluate the water-locking damage, sensitivity damage, permeability enhancement, water-locking removal and sensitivity enhancement contributions of gas reservoir cores under the action of carbon dioxide; the oil reservoir evaluation process can evaluate the bound water damage, injected water damage, residual oil damage, sensitivity damage, permeability enhancement, water-locking removal and residual oil removal effects of oil reservoir cores under the action of carbon dioxide.

[0024] In a specific embodiment, such as Figure 1 As shown, the gas reservoir evaluation process includes the following sub-steps: S11: Obtain at least two standard cores with similar physical properties from the target reservoir and divide them into Group A cores and Group B cores; S12: The core samples from Group A and Group B were pretreated, and their initial absolute permeability under dry conditions was measured and denoted as K. GA1 and K GB1 ; S13: Prepare simulated formation water and fracturing fluid filtrate respectively. Saturate the core sample of group A with the simulated formation water to establish a bound water state, and saturate the core sample of group B with the fracturing fluid filtrate to establish a bound liquid state. Measure the effective gas-phase permeability under the bound state and record it as K. GA2 and K GB2 ; S14: Under target conditions, the core samples from Group A and Group B were subjected to supercritical carbon dioxide immersion. After immersion, the effective gas phase permeability of the core samples while maintaining a liquid-containing state was measured and denoted as K. GA3 and K GB3 ; S15: Dry the core and determine the absolute permeability of the core after drying, denoted as K. GA4 and K GB4 .

[0025] In one specific embodiment, the fracturing fluid degelatinized filtrate is prepared by the following sub-steps: preparing the target gas reservoir fracturing fluid and degelatinizing it to a stable state under simulated reservoir temperature conditions; then injecting the obtained fracturing fluid degelatinized filtrate into the core at a set flow rate or pressure, allowing it to pass through the core pore medium, and collecting the outflow at the core outlet, which is the fracturing fluid degelatinized filtrate.

[0026] In one specific embodiment, step S12 includes pretreatment including washing, drying, and weighing.

[0027] In a specific embodiment, when selecting a gas reservoir evaluation process for experimentation and determining the contribution of carbon dioxide permeation enhancement based on the experimental parameters, the water-locking damage rate D of the core samples from group A is calculated using the following formula. Gw : (1) The permeability enhancement rate I of the core samples from group A is calculated using the following formula. Gp : (2) The water-locking permeability enhancement rate I of the core samples from group A is calculated using the following formula. Gw : (3) The combined damage rate D of water lock and sensitivity in the core samples of Group B was calculated using the following formula. Gt : (4) The pore enlargement and desensitization permeability enhancement rate I of the B group core samples after carbon dioxide treatment is calculated using the following formula. GBd : (5) The dewatering and desensitization permeability enhancement rates (I) of the B group core samples after carbon dioxide treatment are calculated using the following formula. GBw : (6) The sensitivity damage rate D of the core samples from group B is calculated using the following formula. Gs : (7) The dry-state solution-sensitive permeability enhancement rate I of the B group cores was calculated using the following formula. GBs,d : (8) The permeability enhancement rate (I) of the B group core samples was calculated using the following formula. GBs,w : (9).

[0028] In a specific embodiment, such as Figure 2 As shown, the reservoir static evaluation process includes the following sub-steps: S21: Obtain at least two standard cores with similar physical properties from the target reservoir and divide them into Group A cores and Group B cores; S22: The core samples from Group A and Group B were pretreated, and their initial absolute gas permeability under dry conditions was measured and denoted as K. OA1 and K OB1 ; S23: Establish a bound water state for the core samples from group A, and establish a bound water-residual oil state for the core samples from group B. Measure the effective gas-phase permeability under the bound water state, and denote it as K. OA2 and K OB2 ; S24: Under target conditions, the core samples from Group A and Group B were subjected to supercritical carbon dioxide immersion. After immersion, the effective gas permeability of the core samples under confined conditions was measured and denoted as K. OA3 and K OB3 ; S25: Dry the core and measure its absolute permeability after drying, denoted as K. OA4 and K OB4 .

[0029] In the above embodiments, the core samples from group A can be used to evaluate the damage caused by bound water, the effect of pore enlargement, and the effect of water-lock removal; the core samples from group B can be used to evaluate the damage caused by bound water, the damage caused by residual oil, the effect of pore enlargement, the effect of water-lock removal, and the effect of removing residual oil.

[0030] In a specific embodiment, when selecting the reservoir static evaluation process for experiments and determining the contribution of carbon dioxide permeability enhancement based on the experimental parameters, the permeability enhancement rate I of the core samples from group A is calculated using the following formula. OAp : (10) The bound water damage rate D of the core samples from group A was calculated using the following formula. OAw : (11) The water-locking permeability enhancement rate I of the core samples from group A is calculated using the following formula. OAw : (12) The overall damage rate D of the core samples from group B is calculated using the following formula. OBt : (13) The permeability enhancement rate I of the core samples from group B is calculated using the following formula. OBp : (14) The combined permeability enhancement rate I of the core samples from Group B, calculated using the following formula, is obtained by dewatering and derelict residual oil. OBwr : (15) The residual oil damage rate D of the B group core samples was calculated using the following formula. Or : (16) The residual oil contribution rate I of the B group core samples was calculated using the following formula. Or,r : (17).

[0031] In a specific embodiment, such as Figure 3 As shown, the reservoir dynamic evaluation process includes the following sub-steps: S31: Obtain at least two standard cores with similar physical properties from the target reservoir and divide them into Group A cores and Group B cores; S32: The core samples from Group A and Group B were pretreated, and their initial absolute gas permeability under dry conditions was measured and denoted as K. DA1 and K DB1 ; S33: For the saturated or simulated formation water in the core samples of Group A, determine the formation water permeability, denoted as K. DA2 ; The B group core was saturated with simulated formation water, then saturated with formation oil or simulated oil, and displaced using formation water or simulated formation water to establish a residual oil state. The effective permeability of the aqueous phase under the residual oil state was measured and denoted as K. DB2 ; S34: Displace distilled water, inject water, or working fluid into the core samples from Group A and Group B, respectively. After displacing 10-15 PV, maintain the temperature and pressure under simulated reservoir temperature and pressure conditions, and measure the liquid permeability, denoted as K. DA3 and K DB3 ; S35: Nitrogen gas was injected into the core samples from Group A and Group B respectively until no water flow was observed at the outlet. The effective gas-phase permeability under bound water conditions was measured and recorded as K. DA4 and K DB4 ; S36: Under target conditions, supercritical carbon dioxide displacement was performed on the core samples from Group A and Group B. The initial effective gas phase permeability of the carbon dioxide displacement was recorded and denoted as K. DA5 and K DB5 And the stable gas phase effective permeability, denoted as K. DA6 and K DB6 ; S37: After carbon dioxide displacement until permeability stabilizes, the effective gas phase permeability is remeasured using nitrogen and denoted as K. DA7 and K DB7 ; S38: Displace formation water or simulated formation water into the core samples from Group A and Group B respectively, and measure the liquid permeability after the action of carbon dioxide, denoted as K. DA8 and K DB8 ; S39: Dry the core and measure the absolute gas permeability of the dried core, denoted as K. DA9 and K DB9 .

[0032] In the above embodiments, core samples from group A were used to evaluate the effects of injected water damage, bound water damage, sensitivity damage, carbon dioxide pore-enlarging effect, carbon dioxide water-lock dissolving effect, and carbon dioxide sensitivity-reducing and permeability-enhancing effect. Core samples from group B were used to evaluate the effects of injected water damage, residual oil damage, bound water damage, sensitivity damage, carbon dioxide pore-enlarging effect, carbon dioxide water-lock dissolving effect, carbon dioxide sensitivity-reducing and permeability-enhancing effect, and carbon dioxide residual oil dissolving effect under the condition of residual oil presence.

[0033] In a specific embodiment, when selecting the reservoir dynamic evaluation process for experimentation and determining the contribution of carbon dioxide permeation enhancement based on the experimental parameters, the injected water damage rate D of the core samples from group A is calculated using the following formula. DAw : (18) The comprehensive damage rate D of the gas phase channel under the combined effects of bound water and sensitivity in the core samples of Group A is calculated using the following formula. DAg : (19) The comprehensive recovery rate of the carbon dioxide seepage channels affected by core enlargement, water-lock removal, and desensitization in Group A was calculated using the following formula. : (20) The recovery rate of the nitrogen retest channel due to the effects of core enlargement, water-lock removal, and desensitization on group A was calculated using the following formula. : (twenty one) The recovery rate I of carbon dioxide effect on the liquid seepage channel in the core samples of Group A was calculated using the following formula. DA,l : (twenty two) The porosity I of the dry gas seepage channel in the core of Group A is calculated using the following formula. DA,p : (twenty three) The injection water damage rate D under the condition of residual oil presence in the core samples of Group B is calculated using the following formula. DBw : (twenty four) The comprehensive damage rate D of the gas phase channel under the combined effects of residual oil, bound water, and sensitivity in the B group core was calculated using the following formula. DBg : (25) The comprehensive recovery rate of carbon dioxide seepage channels in the B group cores was calculated using the following formula. : (26) The comprehensive recovery rate of the nitrogen retest channel in Group B cores was calculated using the following formula. : (27) The comprehensive recovery rate I of the fluid seepage channels in the B group cores was calculated using the following formula. DB,l : (28) The porosity I of the dry gas seepage channel in the B group core was calculated using the following formula. DB,p : (29) The contribution of residual oil to the restoration of carbon dioxide seepage channels was calculated using the following formula. : (30) The contribution of residual oil to the recovery of the nitrogen retest channel was calculated using the following formula. : (31) The contribution of residual oil to the restoration of the liquid seepage channel is calculated using the following formula. : (32).

[0034] In one specific embodiment, the standard cores with similar physical properties meet at least one of the following conditions: the initial permeability difference does not exceed 20%, the porosity difference does not exceed 10%, the difference in the position of the main peak of the nuclear magnetic resonance T2 spectrum does not exceed 20%, and the difference in the content of major minerals does not exceed 15%.

[0035] In one specific embodiment, the carbon dioxide molar fraction array includes at least three of the following: 0%, 10%, 30%, 50%, 70%, and 100% carbon dioxide molar fractions, preferably at least four of these. During the experiment, the total pressure, temperature, and reaction time are kept consistent across the different carbon dioxide molar fraction arrays. By varying the molar ratios of carbon dioxide with nitrogen, methane, air, or formation gas, the concentration gradient effect formed by the change from high to low molar fractions of carbon dioxide during its migration within the reservoir matrix is ​​simulated.

[0036] In this invention, the experiment can obtain the response relationship between the mole fraction of carbon dioxide and the reservoir stimulation effect, specifically including one or more of the following: the permeability enhancement rate of pore expansion with the mole fraction of carbon dioxide, the permeability enhancement rate of water-lock removal with the mole fraction of carbon dioxide, the permeability enhancement rate of desensitization with the mole fraction of carbon dioxide, the permeability enhancement rate of desensitization with the mole fraction of carbon dioxide, the permeability enhancement rate of desensitization of residual oil with the mole fraction of carbon dioxide, and the rate of reduction of bound water saturation with the mole fraction of carbon dioxide.

[0037] In one specific embodiment, the experiment also includes steps of conducting X-ray diffraction, scanning electron microscopy, nuclear magnetic resonance, CT scanning, contact angle, ion concentration, crude oil composition or water saturation tests on the core or core fragments before and after the action of carbon dioxide, to help determine the mineral dissolution, pore throat enlargement, wettability change, reduction of bound water, relief of sensitive mineral damage and residual oil mobilization mechanism after the action of carbon dioxide.

[0038] In one specific embodiment, the experiment was conducted at a temperature of 40-150 °C, a pressure of 5-60 MPa, a carbon dioxide molar fraction of 0-100%, a static soaking time of 1-168 h, and a dynamic displacement flow rate of 0.01-10 mL / min.

[0039] On the other hand, the present invention also provides a method for optimizing carbon dioxide fracturing construction parameters for oil and gas reservoirs, comprising the following steps: S1: Using any of the above-described methods for identifying carbon dioxide permeability enhancement in oil and gas reservoirs, determine the carbon dioxide permeability enhancement contribution parameters and normalize the carbon dioxide permeability enhancement contribution parameters.

[0040] S2: Construct a comprehensive renovation index model, and calculate the comprehensive renovation index under different carbon dioxide mole fractions based on the comprehensive renovation index model.

[0041] In a specific embodiment, when the oil and gas reservoir carbon dioxide permeability enhancement identification method uses the gas reservoir evaluation process to obtain experimental parameters in step S1, the comprehensive stimulation index model in this step is: (34) In the formula: The comprehensive transformation index under the gas reservoir evaluation process; The mole fraction of carbon dioxide; Normalized pore-expanding permeability enhancement rate; To normalize and resolve water-locking and infiltration rate; To normalize and resolve the sensitive permeability rate; Permeability sensitivity of dry-state solutions from Group B cores and permeability sensitive to liquid hydrolysis The mean value is obtained by normalization, that is ; When the oil and gas reservoir carbon dioxide permeability enhancement identification method in step S1 uses the reservoir static evaluation process to obtain experimental parameters, the comprehensive stimulation index model in this step is: (35) In the formula: The comprehensive stimulation index under the static evaluation process of the reservoir; The normalized permeability enhancement rate corresponds to the permeability enhancement rate of reservoir group B. ; To normalize the water-locking permeability enhancement rate, the corresponding water-locking permeability enhancement rate for reservoir A group. ; The normalized residual oil utilization contribution rate corresponds to the residual oil contribution rate of reservoir group B solution. ; When the oil and gas reservoir carbon dioxide permeability enhancement identification method in step S1 uses the reservoir dynamic evaluation process to obtain experimental parameters, the comprehensive stimulation index model in this step is: (36) In the formula: The comprehensive stimulation index under the dynamic evaluation process of oil reservoirs; The normalized overall recovery rate of carbon dioxide seepage channels corresponds to the overall recovery rate of carbon dioxide seepage channels in reservoir group B. ; The normalized nitrogen retest channel comprehensive recovery rate corresponds to the nitrogen retest channel comprehensive recovery rate in reservoir group B. ; The normalized comprehensive recovery rate of liquid seepage channels corresponds to the comprehensive recovery rate of liquid seepage channels in reservoir group B. ; The normalized dry gas seepage channel expansion rate corresponds to the dry gas seepage channel expansion rate in reservoir group B. .

[0042] S3: Select the range of carbon dioxide mole fraction corresponding to the threshold of the comprehensive transformation index as the recommended carbon dioxide mole fraction window for the target reservoir.

[0043] S4: Input the recommended carbon dioxide mole fraction window and the corresponding carbon dioxide permeability enhancement contribution parameters into the fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-steaming model, simulate and evaluate different combinations of carbon dioxide fracturing construction parameters, and determine the recommended carbon dioxide fracturing construction parameters for the target reservoir based on the evaluation results. The fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-well shut-in model is as follows: (33) In the formula: A fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-well shut-in model; This refers to the combination of parameters for carbon dioxide fracturing operations. For stress tensor; This is a physical activity item; For total damage variable; This represents the initial elastic stiffness tensor in the undamaged state. This is the total strain tensor; This is the initial strain tensor; The coefficient of thermal expansion of the rock; For temperature; For reference temperature; Unit tensor; Porosity; t is the fluid density; t is time. Darcy flow velocity; For quality source items; For penetration rate; For fluid viscosity; Pore ​​pressure; Equivalent volumetric heat capacity; The specific heat capacity at constant pressure of the fluid; It is the equivalent thermal conductivity; For heat source items; This represents the carbon dioxide diffusion flux; This refers to the molar concentration of carbon dioxide. For the reaction term; For source and sink items; The effective diffusion coefficient; This represents the mole fraction of carbon dioxide. Initial penetration rate; Initial porosity; The permeability evolution factor is determined by both the mole fraction of carbon dioxide and the reaction time.

[0044] In this invention, the fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-well-steaming model is composed of a rock deformation-damage sub-model, a fluid seepage sub-model, a temperature transfer sub-model, a carbon dioxide mole fraction transport sub-model, and a porosity-permeability dynamic evolution sub-model coupled together, which can accurately simulate the fracturing effect of carbon dioxide fracturing.

[0045] In a specific embodiment, when conducting simulation evaluation, the carbon dioxide fracturing construction parameters include any one or more of the following: carbon dioxide mole fraction, pump injection rate, total carbon dioxide injection volume, construction pressure, injection time, well shut-in time, single-segment length, cluster spacing, number of clusters in a single segment, carbon dioxide and auxiliary gas mixing ratio, wellbore injection temperature, and target fracturing segment.

[0046] The evaluation indicators used include any one or more of the following: crack length, crack height, crack width, modification volume, increase in matrix permeability, decrease in bound water saturation, residual oil utilization, predicted production capacity, carbon dioxide utilization efficiency, and construction pressure safety limit.

[0047] The construction parameter combination that satisfies the effective transformation constraint is determined as follows: the fracture area ratio is not less than the fracture area ratio threshold, the comprehensive effective transformation coefficient is not less than the comprehensive effective transformation coefficient threshold, the well stagnation and permeability enhancement contribution coefficient is not less than the well stagnation and permeability enhancement contribution threshold, and the maximum construction pressure does not exceed the construction safety pressure limit. Among the construction parameter combinations that satisfy the effective transformation constraint, the construction parameter combination with the highest carbon dioxide utilization efficiency or the lowest total carbon dioxide injection volume is selected as the recommended carbon dioxide fracturing construction parameter.

[0048] In a specific embodiment, the fracture area ratio, the comprehensive effective stimulation coefficient, and the well stagnation permeability enhancement contribution coefficient are calculated using the following formulas: (37) (38) (39) In the formula: This represents the percentage of the crack area. This is the reservoir calculation region; This indicates an indicator function; it takes the value 1 if the condition within the parentheses is true, and 0 otherwise. For damage variables; The threshold for damage assessment; To comprehensively assess the effective transformation coefficient; , , These are the area percentages of areas that have not been fully renovated, areas that have been effectively renovated, and areas that have been over-renovated, respectively. , The weights are calculated for areas that have not been adequately upgraded and areas that have been over-upgraded, respectively. The area of ​​the i-th carbon dioxide mole fraction zone is the proportion of the total matrix area. The subscript i is L, M or H, representing the insufficiently modified zone, the effectively modified zone and the over-modified zone. Areas of zones with different carbon dioxide mole fractions; The total area of ​​the matrix; To determine the threshold for comprehensive and effective transformation coefficients; Contribution coefficient to well permeability enhancement during well sealing; For well simmering time The overall effective transformation coefficient after the transformation; This is the comprehensive effective modification coefficient before the well is sealed.

[0049] In this invention, the recommended carbon dioxide mole fraction window obtained from the gas reservoir evaluation process, the oil reservoir static evaluation process, or the oil reservoir dynamic evaluation process can be used as the concentration constraint condition for the optimal selection of carbon dioxide fracturing construction parameters. One or more of the following parameters obtained under the corresponding mole fraction—pore enlargement and permeability enhancement rate, water-lock removal and permeability enhancement rate, sensitivity removal and permeability enhancement rate, residual oil mobilization contribution rate, comprehensive recovery rate of carbon dioxide seepage channels, comprehensive recovery rate of nitrogen retest channels, comprehensive recovery rate of liquid seepage channels, and pore enlargement rate of dry gas seepage channels—can be used as matrix stimulation parameters input into the fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-well-shutting model. Through this fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-well-shutting model, it is possible to calculate fracture length, fracture height, fracture width, stimulation volume, matrix permeability improvement, bound water saturation reduction, residual oil mobilization degree, predicted production capacity, and carbon dioxide utilization efficiency under different combinations of construction parameters, thereby optimizing the recommended carbon dioxide fracturing construction parameters based on the calculation results.

[0050] In one specific embodiment, the target oil and gas reservoir is any one of tight sandstone, shale, volcanic rock, carbonate rock, or coal rock.

[0051] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention in any way. Although the present invention has been disclosed above with reference to preferred embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some modifications or alterations to the above-disclosed technical content to create equivalent embodiments without departing from the scope of the present invention. Any simple modifications, equivalent changes, and alterations made to the above embodiments based on the technical essence of the present invention without departing from the scope of the present invention shall still fall within the scope of the present invention.

Claims

1. A method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs, characterized in that, Includes the following steps: Based on the reservoir type of the target reservoir, either a gas reservoir evaluation process or an oil reservoir evaluation process is selected to conduct experiments and obtain experimental parameters. The oil reservoir evaluation process includes a static oil reservoir evaluation process and / or a dynamic oil reservoir evaluation process. During the experiment, at least three different carbon dioxide molar fraction groups were set up under the same temperature, pressure, action time and fluid saturation conditions. The carbon dioxide molar fraction groups were formed by mixing carbon dioxide with one or more of nitrogen, methane, air or formation gas, and the total pressure of each group was kept consistent. The experiment was repeated under each carbon dioxide molar fraction group. The contribution of carbon dioxide to osmosis was determined based on the experimental parameters.

2. The method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs according to claim 1, characterized in that, The gas reservoir evaluation process includes the following sub-steps: S11: Obtain at least two standard cores with similar physical properties from the target reservoir and divide them into Group A cores and Group B cores; S12: The core samples from Group A and Group B were pretreated, and their initial absolute permeability under dry conditions was measured and denoted as K. GA1 and K GB1 ; S13: Prepare simulated formation water and fracturing fluid filtrate respectively. Saturate the core sample of group A with the simulated formation water to establish a bound water state, and saturate the core sample of group B with the fracturing fluid filtrate to establish a bound liquid state. Measure the effective gas-phase permeability under the bound state and record it as K. GA2 and K GB2 ; S14: Under target conditions, the core samples from Group A and Group B were subjected to supercritical carbon dioxide immersion. After immersion, the effective gas phase permeability of the core samples while maintaining a liquid-containing state was measured and denoted as K. GA3 and K GB3 ; S15: Dry the core and determine the absolute permeability of the core after drying, denoted as K. GA4 and K GB4 .

3. The method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs according to claim 2, characterized in that, When determining the contribution of carbon dioxide permeation enhancement based on the experimental parameters, the water-locking damage rate D of the core samples from group A is calculated using the following formula. Gw : （1） The permeability enhancement rate I of the core samples from group A is calculated using the following formula. Gp : （2） The water-locking permeability enhancement rate I of the core samples from group A is calculated using the following formula. Gw : （3） The combined damage rate D of water lock and sensitivity in the core samples of Group B was calculated using the following formula. Gt : （4） The pore enlargement and desensitization permeability enhancement rate I of the B group core samples after carbon dioxide treatment is calculated using the following formula. GBd : （5） The dewatering and desensitization permeability enhancement rates (I) of the B group core samples after carbon dioxide treatment are calculated using the following formula. GBw : （6） The sensitivity damage rate D of the core samples from group B is calculated using the following formula. Gs : （7） The dry-state solution-sensitive permeability enhancement rate I of the B group cores was calculated using the following formula. GBs,d : （8） The permeability enhancement rate (I) of the B group core samples was calculated using the following formula. GBs,w : （9）。 4. The method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs according to claim 1, characterized in that, The reservoir static evaluation process includes the following sub-steps: S21: Obtain at least two standard cores with similar physical properties from the target reservoir and divide them into Group A cores and Group B cores; S22: The core samples from Group A and Group B were pretreated, and their initial absolute gas permeability under dry conditions was measured and denoted as K. OA1 and K OB1 ; S23: Establish a bound water state for the core samples from group A, and establish a bound water-residual oil state for the core samples from group B. Measure the effective gas-phase permeability under the bound water state, and denote it as K. OA2 and K OB2 ; S24: Under target conditions, the core samples from Group A and Group B were subjected to supercritical carbon dioxide immersion. After immersion, the effective gas permeability of the core samples under confined conditions was measured and denoted as K. OA3 and K OB3 ; S25: Dry the core and measure its absolute permeability after drying, denoted as K. OA4 and K OB4 .

5. The method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs according to claim 4, characterized in that, When determining the contribution of carbon dioxide permeability enhancement based on the experimental parameters, the permeability enhancement rate I of the core sample from group A is calculated using the following formula. OAp : （10） The bound water damage rate D of the core samples from group A was calculated using the following formula. OAw : （11） The water-locking permeability enhancement rate I of the core samples from group A is calculated using the following formula. OAw : （12） The overall damage rate D of the core samples from group B is calculated using the following formula. OBt : （13） The permeability enhancement rate I of the core samples from group B is calculated using the following formula. OBp : （14） The combined permeability enhancement rate I of the core samples from Group B, calculated using the following formula, is obtained by dewatering and derelict residual oil. OBwr : （15） The residual oil damage rate D of the B group core samples was calculated using the following formula. Or : （16） The residual oil contribution rate I of the B group core samples was calculated using the following formula. Or,r : （17）。 6. The method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs according to claim 1, characterized in that, The reservoir dynamic evaluation process includes the following sub-steps: S31: Obtain at least two standard cores with similar physical properties from the target reservoir and divide them into Group A cores and Group B cores; S32: The core samples from Group A and Group B were pretreated, and their initial absolute gas permeability under dry conditions was measured and denoted as K. DA1 and K DB1 ; S33: For the saturated or simulated formation water in the core samples of Group A, determine the formation water permeability, denoted as K. DA2 ; The B group core was saturated with simulated formation water, then saturated with formation oil or simulated oil, and displaced using formation water or simulated formation water to establish a residual oil state. The effective permeability of the aqueous phase under the residual oil state was measured and denoted as K. DB2 ; S34: Displace distilled water, inject water or working fluid into the core samples from Group A and Group B respectively, displacing 10-15 PV. After maintaining the temperature and pressure under simulated reservoir temperature and pressure conditions, measure the liquid permeability and record it as K. DA3 and K DB3 ; S35: Nitrogen gas was injected into the core samples from Group A and Group B respectively until no water flow was observed at the outlet. The effective gas-phase permeability under bound water conditions was measured and recorded as K. DA4 and K DB4 ; S36: Under target conditions, supercritical carbon dioxide displacement was performed on the core samples from Group A and Group B. The initial effective gas phase permeability of the carbon dioxide displacement was recorded and denoted as K. DA5 and K DB5 And the stable gas phase effective permeability, denoted as K. DA6 and K DB6 ; S37: After carbon dioxide displacement until permeability stabilizes, the effective gas phase permeability is remeasured using nitrogen and denoted as K. DA7 and K DB7 ; S38: Displace formation water or simulated formation water into the core samples from Group A and Group B respectively, and measure the liquid permeability after the action of carbon dioxide, denoted as K. DA8 and K DB8 ; S39: Dry the core and measure the absolute gas permeability of the dried core, denoted as K. DA9 and K DB9 .

7. The method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs according to claim 6, characterized in that, When determining the contribution of carbon dioxide permeation enhancement based on the experimental parameters, the injected water damage rate D of the core samples from group A is calculated using the following formula. DAw : （18） The comprehensive damage rate D of the gas phase channel under the combined effects of bound water and sensitivity in the core samples of Group A is calculated using the following formula. DAg : （19） The comprehensive recovery rate of the carbon dioxide seepage channels affected by core enlargement, water-lock removal, and desensitization in Group A was calculated using the following formula. : （20） The recovery rate of the nitrogen retest channel due to the effects of core enlargement, water-lock removal, and desensitization on group A was calculated using the following formula. : （21） The recovery rate I of carbon dioxide effect on the liquid seepage channel in the core samples of Group A was calculated using the following formula. DA,l : （22） The porosity I of the dry gas seepage channel in the core of Group A is calculated using the following formula. DA,p : （23） The injection water damage rate D under the condition of residual oil presence in the core samples of Group B is calculated using the following formula. DBw : （24） The comprehensive damage rate D of the gas phase channel under the combined effects of residual oil, bound water, and sensitivity in the B group core was calculated using the following formula. DBg : （25） The comprehensive recovery rate of carbon dioxide seepage channels in the B group cores was calculated using the following formula. : （26） The comprehensive recovery rate of the nitrogen retest channel in Group B cores was calculated using the following formula. : （27） The comprehensive recovery rate I of the fluid seepage channels in the B group cores was calculated using the following formula. DB,l : （28） The porosity I of the dry gas seepage channel in the B group core was calculated using the following formula. DB,p : （29） The contribution of residual oil to the restoration of carbon dioxide seepage channels was calculated using the following formula. : （30） The contribution of residual oil to the recovery of the nitrogen retest channel was calculated using the following formula. : （31） The contribution of residual oil to the restoration of the liquid seepage channel is calculated using the following formula. : （32）。 8. The method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs according to claim 2, 4, or 6, characterized in that, The standard cores with similar physical properties meet at least one of the following conditions: the difference in initial permeability does not exceed 20%, the difference in porosity does not exceed 10%, the difference in the position of the main peak in the nuclear magnetic resonance T2 spectrum does not exceed 20%, and the difference in the content of major minerals does not exceed 15%.

9. A method for optimizing carbon dioxide fracturing construction parameters in oil and gas reservoirs, characterized in that, Includes the following steps: S1: Using the method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs as described in any one of claims 1-8, determine the carbon dioxide permeability enhancement contribution parameters, and normalize the carbon dioxide permeability enhancement contribution parameters. S2: Construct a comprehensive renovation index model, and calculate the comprehensive renovation index under different carbon dioxide mole fractions based on the comprehensive renovation index model; S3: Select the range of carbon dioxide mole fraction corresponding to the threshold of the comprehensive transformation index as the recommended carbon dioxide mole fraction window of the target reservoir; S4: Input the recommended carbon dioxide mole fraction window and the corresponding carbon dioxide permeability enhancement contribution parameters into the fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-steaming model, simulate and evaluate different combinations of carbon dioxide fracturing construction parameters, and determine the recommended carbon dioxide fracturing construction parameters for the target reservoir based on the evaluation results. The fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-well shut-in model is as follows: （33） In the formula: A fluid-solid-thermal-chemical multi-field coupled carbon dioxide fracturing-well shut-in model; This refers to the combination of parameters for carbon dioxide fracturing operations. For stress tensor; This is a physical activity item; For total damage variable; This represents the initial elastic stiffness tensor in the undamaged state. This is the total strain tensor; This is the initial strain tensor; The coefficient of thermal expansion of the rock; For temperature; For reference temperature; Unit tensor; Porosity; t is the fluid density; t is time. Darcy flow velocity; For quality source items; For penetration rate; For fluid viscosity; Pore ​​pressure; Equivalent volumetric heat capacity; The specific heat capacity at constant pressure of the fluid; It is the equivalent thermal conductivity; For heat source items; This represents the carbon dioxide diffusion flux; This refers to the molar concentration of carbon dioxide. For the reaction term; For source and sink items; The effective diffusion coefficient; This represents the mole fraction of carbon dioxide. Initial penetration rate; Initial porosity; The permeability evolution factor is determined by both the mole fraction of carbon dioxide and the reaction time.

10. The method for optimizing carbon dioxide fracturing construction parameters for oil and gas reservoirs according to claim 9, characterized in that, When, in step S1, the method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs uses a gas reservoir evaluation process to obtain experimental parameters, the comprehensive stimulation index model in step S2 is: （34） In the formula: The comprehensive transformation index under the gas reservoir evaluation process; The mole fraction of carbon dioxide; Normalized pore-expanding permeability enhancement rate; To normalize and resolve water-locking and infiltration rate; To normalize and resolve the sensitive permeability rate; When, in step S1, the method for identifying carbon dioxide permeability enhancement in oil and gas reservoirs uses the reservoir static evaluation process to obtain experimental parameters, the comprehensive stimulation index model in step S2 is: （35） In the formula: The comprehensive stimulation index under the static evaluation process of the reservoir; Normalized pore-expanding permeability enhancement rate; To normalize and resolve water-locking and infiltration rate; Contribution rate to normalized residual oil utilization; When, in step S1, the oil and gas reservoir carbon dioxide permeability enhancement identification method uses the reservoir dynamic evaluation process to obtain experimental parameters, the comprehensive stimulation index model in step S2 is: （36） In the formula: The comprehensive stimulation index under the dynamic evaluation process of oil reservoirs; The normalized overall recovery rate of carbon dioxide seepage channels; The normalized nitrogen retest channel comprehensive recovery rate; The normalized overall recovery rate of the liquid seepage channel; The normalized porosity of the dry gas seepage channel.

Images